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Exhibit 99(d)
[Excerpt from NorAm 1996 Form 10-K]
1. ACCOUNTING POLICIES AND COMPONENTS OF
CERTAIN FINANCIAL STATEMENT LINE ITEMS
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of NorAm
Energy Corp. and its subsidiaries, all of which are wholly owned, and all
significant affiliated transactions and balances have been eliminated. As used
herein, "NorAm" and "the Company" refer to NorAm Energy Corp. and its
consolidated subsidiaries. Certain prior period amounts have been reclassified
to conform to current presentation.
MERGER WITH HOUSTON INDUSTRIES
On August 11, 1996, the Company entered into an Agreement and Plan of Merger
(the "Merger Agreement") with Houston Industries Incorporated ("Houston
Industries" or "HI"), Houston Lighting & Power Company ("HL&P") and a newly
formed Delaware subsidiary of Houston Industries ("HI Merger, Inc."). Under the
Merger Agreement, the Company would merge with and into HI Merger, Inc. and
would become a wholly owned subsidiary of HII (as defined following). Houston
Industries would merge with and into HL&P, which would be renamed Houston
Industries Incorporated ("HII") (the term "Transaction" refers to the business
combination between Houston Industries and the Company). Consideration for the
purchase of the Company's common stock would be a combination of cash and shares
of HI common stock, valued at approximately $3.8 billion, consisting of
approximately $2.4 billion for the Company's common stock and equivalents and
approximately $1.4 billion in assumption of the Company's debt. Additional
information concerning the Merger Agreement is contained in the Joint Proxy
Statement/Prospectus of Houston Industries, HL&P and the Company dated October
29, 1996 ("the Proxy/Prospectus").
The Merger Agreement was approved and adopted at Special Meetings of
Houston Industries' and the Company's stockholders held on December 17, 1996.
The Company and HI proceeded to obtain required state and municipal regulatory
approvals, all of which have been obtained, and to request an exemption from the
Securities and Exchange Commission ("the SEC") which would allow the Transaction
to take place under its preferred structure without subjecting post-merger HII
to the requirements of the Public Utility Holding Company Act. It is HI's and
the Company's intention to defer the closing of the Transaction until the SEC
issues its ruling on the exemption request although, as set forth in the
Proxy/Prospectus, there are two alternative structures, one of which would not
require SEC approval. Adoption of either of these structures, however, would
require that the Company and HI make new filings to obtain the various state and
municipal regulatory approvals.
In early February 1997, the Federal Energy Regulatory Commission ("the
FERC" or "the Commission") issued an order ("the Order") advising the Company
that the Transaction "...may require Commission approval pursuant to section 203
of the FPA" ( the "FPA" refers to the Federal Power Act), and directing the
Company to file a response within 30 days of the Order either "...(1) providing
arguments as to why the transaction does not require Commission authorization
under section 203 or (2) an application under section 203". In early March 1997,
the Company filed a response to the Order stating its view that the FERC does
not have jurisdiction over the Transaction. Although such response disclaimed
any FERC jurisdiction over the Transaction, it also indicated that one option
being considered was to file an application with the FERC for approval of the
Transaction in anticipation of an expedited review under the FERC's newly-issued
merger policy guidelines. On March 27, 1997, the Company filed an application
under section 203 of the FPA seeking FERC approval of the Transaction, although
continuing to assert its position that such approval is not required.
The Company continues to believe that the Transaction will be completed as
contemplated although, in light of the pending regulatory issues as set forth
preceding, the Company cannot predict with any degree of certainty when the
Transaction will be consummated.
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NATURE OF OPERATIONS
The Company's principal activities are in the natural gas industry (representing
in excess of 90% of the Company's total revenues, income or loss and
identifiable assets), primarily in the contiguous 48 states, with principal
operations in Texas, Louisiana, Mississippi, Arkansas, Oklahoma, Missouri and
Minnesota. The Company has operations in various phases of the natural gas
industry, including distribution, transmission, marketing and gathering which,
during 1996, provided approximately 50.5%, 34.2%, 11.5% and 3.8%, respectively,
of the Company's consolidated operating income (exclusive of the net operating
loss attributable to Corporate and certain miscellaneous activities). The
Company's distribution operations are conducted by its Entex, Minnegasco and
Arkla divisions, its interstate pipeline operations are conducted by NorAm Gas
Transmission Company ("NGT") and Mississippi River Transmission Corporation
("MRT"), its marketing activities are conducted by NorAm Energy Services, Inc.
("NES") and NorAm Energy Management, Inc. ("NEM"), and its gathering activities
are conducted by NorAm Field Services Corp. ("NFS"), in each case also including
certain subsidiaries and affiliates. The Company's miscellaneous activities,
whose collective results of operations currently are not material, principally
consist of home care services, including (1) appliance sales and service, (2)
home security services, (3) utility services, principally line locating and (4)
resale of long distance telephone service. The Company expects to make an
investment in international activities as discussed following.
During 1996, the Company had revenues of $55 million, approximately 1% of
consolidated operating revenues, from sales to and transportation for Laclede
Gas Company (the local natural gas distribution company which serves the greater
St. Louis, Illinois area) pursuant to several long-term firm transportation and
storage agreements which expire in 1999. The Company's interstate pipelines
received revenues of approximately $163.8 million in 1996 from services provided
to the Company's Arkla distribution division pursuant to several agreements,
representing approximately 3.4% of consolidated operating revenues and
approximately 47.2% of NGT's and MRT's combined operating revenues. With respect
to services provided to Arkla in (1) Arkansas, the current service agreement is
scheduled to expire in April 2002 and (2) Louisiana, Oklahoma and East Texas,
the process of negotiation and regulatory approval has not yet been completed,
but the Company currently expects to obtain revised agreements with a term
similar to that currently in effect for Arkansas.
In early 1997, the Company learned that four consortiums ("the
Consortiums"), each of which included the Company, were the apparent successful
bidders for the right to build and operate natural gas distribution facilities
in each of four defined service areas ("the Concessions") within Colombia.
Contracts, which extend through the year 2014 and grant the exclusive right to
distribute gas to consumers of less than 500 Mcf per day (and the right to
compete for other customers), are expected to be awarded in April 1997. The
Company estimates that the Concessions ultimately will have approximately
400,000 customers, connected over approximately a five-year period at a total
cost of approximately $160 million, with construction expected to begin no later
than the fourth quarter of 1997. The Company's ownership interest in the
Consortiums, while subject to change through continuing negotiations with its
existing and potential partners ranges from 15% to approximately 33% and, based
on the expected number of customers, represents a weighted average ownership
interest of approximately 23%.
In January 1997, the Company participated in a bid for a permit authorizing
the construction, ownership and operation of a natural gas distribution system
for the geographic area that includes the cities of Chihuahua, Delicias and
Cuauchtemoc/Anahuac in North Central Mexico. In March 1997, the Company learned
that its group was not the successful bidder. The Company had previously
announced its intention to participate in a similar bidding process for a permit
to provide natural gas distribution service to all or a portion of Mexico City,
although no date has yet been set for submission of bids.
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USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from those estimates.
RATE REGULATION
Methods of allocating costs to accounting periods in the portion of the
Company's business subject to federal, state or local rate regulation may differ
from methods generally applied by unregulated companies. However, when
accounting allocations prescribed by regulatory authorities are used for
rate-making, the resultant accounting follows the concept of matching costs with
related revenues. The Company's rate-regulated divisions/subsidiaries bill
customers on a monthly cycle billing basis. Revenues are recorded on an accrual
basis, including an estimate for gas delivered but unbilled at the end of each
accounting period.
All of the Company's rate-regulated businesses historically have followed
the accounting guidance contained in Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71").
The Company discontinued application of SFAS 71 to NGT effective with year-end
1992 reporting. As a result of the continued application of SFAS 71 to MRT and
the Company's distribution divisions, the accompanying consolidated financial
statements contain certain assets and liabilities which would not be recognized
by unregulated entities. In addition to regulatory assets related to
postretirement benefits other than pensions (see Note 5), the Company's only
other significant regulatory asset is related to anticipated environmental
remediation costs, see "Accounting for Remediation Costs" following and
"Environmental Matters" included in Note 7.
CHANGE IN ACCOUNTING ESTIMATE
Pursuant to a revised study of the useful lives of certain assets, in July 1995,
the Company changed the depreciation rates associated with certain of its
natural gas gathering and pipeline assets. This change had the effect of
increasing 1995 "Income before extraordinary item" and "Net income" by
approximately $3.2 million ($0.03 per share).
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES
To reduce the risk from market fluctuations in the price of natural gas and
related transportation, the Company enters into futures transactions, swaps and
options (collectively, "financial instruments") in order to hedge certain
natural gas in storage, as well as certain expected purchases, sales and
transportation of natural gas, a portion of which are firm commitments at the
inception of the hedge. Some of these financial instruments carry
off-balance-sheet risk, see "Credit Risk and Off-Balance-Sheet Risk" included in
Note 7. Changes in the market value of these financial instruments utilized as
hedges are (1) recognized as an adjustment of the carrying value in the case of
existing assets and liabilities, (2) included in the measurement of the
transaction that satisfies the commitment in the case of firm commitments and
(3) included in the measurement of the subsequent transaction in the case of
anticipated transactions, whether or not the hedge is closed out before the date
of the anticipated transaction. In cases where anticipated transactions do not
occur, deferred gains and losses are recognized when such transactions were
scheduled to occur.
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ACCOUNTING FOR REMEDIATION COSTS
Environmental remediation costs are accrued when the Company determines that it
is probable that it will incur such costs and the amount is reasonably
estimable. To the extent that potential environmental remediation costs are
quantified within a range, the Company establishes reserves equal to the most
likely level of costs within the range and adjusts such accruals as better
information becomes available. In determining the amount of the liability,
future costs are not discounted to their present value and the liability is not
offset by expected insurance recoveries. If justified by circumstances within
the Company's business subject to SFAS 71, corresponding regulatory assets are
recorded in anticipation of recovery through the ratemaking process, see
"Environmental Matters" included in Note 7.
EARLY RETIREMENT AND SEVERANCE
During the first quarter of 1996, the Company instituted a reorganization plan
affecting its NGT and MRT subsidiaries, pursuant to which a total of
approximately 275 positions were eliminated, resulting in expense for severance
payments and enhanced retirement benefits. Also during the first quarter of
1996, (1) the Company's Entex division instituted an early retirement program
which was accepted by approximately 100 employees and (2) the Company's
Minnegasco division reorganized certain functions, resulting in the elimination
of approximately 25 positions. Collectively, these programs resulted in a
non-recurring pre-tax charge of approximately $22.3 million (approximately $13.4
million or $0.10 per share after tax), which pre-tax amount is reported in the
accompanying Statement of Consolidated Income as "Early retirement and
severance".
INTEREST EXPENSE
Interest expense includes, where applicable, amortization of debt issuance cost
and amortization of gains and losses on interest rate hedging transactions
related to the Company's debt financing activities, see Note 3. "Interest
expense, net" as presented in the accompanying Statement of Consolidated Income
is net of an allowance for borrowed funds used during construction of $1.6
million, $1.1 million and $1.3 million in 1996, 1995 and 1994, respectively.
Beginning in 1997, amounts previously reported as "Loss on sale of receivables"
will be reported as a component of interest expense, see "Sale of Receivables"
included in Note 3.
DISCONTINUED OPERATIONS
"Loss from discontinued operations, less taxes" as presented in the accompanying
Statement of Consolidated Income for 1994 represents a pre-tax loss of $3.3
million (the associated tax benefit was $1.2 million) resulting from litigation
associated with the discontinued operations of University Savings Association, a
former subsidiary of Entex.
EARNINGS PER SHARE
Primary earnings per share is computed using the weighted average number of
shares of the Company's Common Stock ("Common Stock") actually outstanding
during each period presented. Outstanding options for purchase of Common Stock,
the Company's only "common stock equivalent" as that term is defined in the
authoritative accounting literature, have been excluded due to either (1) the
fact that the options would have been anti-dilutive if exercised or (2) the
immaterial impact which would result from the exercise of those options which
are currently exercisable and would be dilutive if exercised. Fully diluted
earnings per share, in addition to the actual weighted average common shares
outstanding, assumes the conversion, as of its issuance date of June 17, 1996,
of the 3,450,000 shares of the Trust Preferred (see Note 3) at a conversion rate
of 4.1237 shares of Common Stock for each share of the Trust Preferred
(resulting in the assumed issuance of a total of 14,226,765 shares of Common
Stock), and reflects the increase in earnings from the cessation of the
dividends on the Trust Preferred (net of the related tax benefit) which would
result from such assumed conversion. For 1996, this assumed earnings increase
was approximately $3.5 million, net of related tax benefits of approximately
$2.3 million. The Company's 6% Convertible Subordinated Debentures due 2012 (see
"Other Long-Term Financing" included in Note 3) and the Company's $3.00 Series A
Preferred Stock (prior to its June 1996 exchange, see "Other Long-Term
Financing" included in Note 3), due to their exchange rates, are anti-dilutive
and are therefore excluded from all earnings per share calculations. During the
periods in which the Company's $3.00 Convertible Exchangeable Preferred Stock,
Series A was outstanding, earnings per share from continuing operations is
calculated after reduction for the preferred stock dividend requirement
associated with such security.
In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting
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Standards No. 128, "Earnings per Share" ("SFAS 128"), which is required to be
implemented for fiscal years ending after December 15, 1997 and earlier
application is not permitted. SFAS 128 replaces the current "primary earnings
per share" ("primary EPS") and "fully diluted earnings per share" ("fully
diluted EPS") with "basic earnings per share" ("basic EPS") and "diluted
earnings per share" ("diluted EPS"). Unlike the calculation of primary EPS which
includes, in its denominator, the sum of (1) actual weighted shares outstanding
and (2) "common stock equivalents" as that term is defined in the authoritative
literature, basic EPS is calculated using only the actual weighted average
shares outstanding during the relevant periods. Diluted EPS is very similar to
fully diluted EPS, differing only in technical ways which do not currently
affect the Company.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, in general, is carried at cost and depreciated or
amortized on a straight-line basis over its estimated useful life. Additions to
and betterments of utility property are charged to property accounts at cost,
while the costs of maintenance, repairs and minor replacements are charged to
expense as incurred. Upon normal retirement of units of utility property, plant
and equipment, the cost of such property, together with cost of removal less
salvage, is charged to accumulated depreciation. Costs of individually
significant internally developed and purchased computer software systems are
capitalized and amortized over their expected useful life.
INVESTMENTS AND OTHER ASSETS
Goodwill, none of which is being recovered in regulated service rates, is
amortized on a straight-line basis over 40 years. Approximately $14.2 million of
goodwill was amortized each year during 1996, 1995 and 1994. Accumulated
amortization of goodwill was $103.4 million and $89.2 million at December 31,
1996 and 1995, respectively. The Company periodically compares the carrying
value of its goodwill to the anticipated undiscounted future operating income
from the businesses whose acquisition gave rise to the goodwill and, as yet, no
impairment is indicated or expected.
Itron, Inc. ("Itron") is a publicly-traded Spokane, Washington company which
manufactures and markets automated meter-reading devices and provides related
services. The Company accounts for its investment in Itron utilizing the cost
method (its ownership of approximately 1.5 million Itron common shares at
December 31, 1996 represented an ownership interest of approximately 11.2%),
revalues its investment to market value as of each balance sheet date and
reports any unrealized gain or loss, net of tax, as a separate component of
stockholders' equity, which unrealized gain was immaterial at December 31, 1996.
During 1996, the market value of the Company's Itron investment (based on
closing share prices on the NASDAQ) varied from a high of approximately $88.3
million to a low of approximately $22.5 million. At March 14, 1997, the market
value of the Company's investment in Itron was approximately $29.3 million and
the unrealized gain was approximately $1.7 million (net of tax benefit of $1.0
million).
ALLOWANCE FOR DOUBTFUL ACCOUNTS
"Accounts and notes receivable, principally customer" as presented in the
accompanying Consolidated Balance Sheet are net of an allowance for doubtful
accounts of $13.0 million and $11.1 million at December 31, 1996 and 1995,
respectively.
INVENTORIES
Inventories principally follow the average cost method and all non-utility
inventories held for resale are valued at the lower of cost or market.
ACCOUNTS PAYABLE
Certain of the Company's cash balances reflect credit balances to the extent
that checks written have not yet been presented for payment. Such balances
included in "Accounts payable, principally trade" in the accompanying
Consolidated Balance Sheet were approximately $53.5 million and $44.4 million at
December 31, 1996 and 1995, respectively.
STATEMENT OF CONSOLIDATED CASH FLOWS
The accompanying Statement of Consolidated Cash Flows reflects the assumption
that all highly liquid investments
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purchased with original maturities of three months or less are cash equivalents.
Cash flows resulting from the Company's risk management (hedging) activities are
classified in the accompanying Statement of Consolidated Cash Flows in the same
category as the item being hedged.
In September 1994, the Company sold all of its Kansas distribution properties,
serving approximately 23,000 customers in 14 communities, together with certain
related pipeline assets, for approximately $23 million in cash, approximately
its carrying value, shown in the accompanying Statement of Consolidated Cash
Flows as "Sale of distribution properties".
In June 1996, the Company exercised its right to exchange its $3.00 Convertible
Exchangeable Preferred Stock, Series A for its 6% Convertible Subordinated
Debentures due 2012 in a non-cash transaction. The Company issues its common
stock in conjunction with certain compensation plans. For additional information
on these matters, see Note 6 and "Other Long-Term Financing" included in Note 3.
Following is certain supplemental cash flow information:
The caption "Changes in certain asset and liabilities, net of noncash
transactions" as shown in the accompanying Statement of Consolidated Cash Flows
includes the following:
(1) Beginning with January 1, 1997, cash flows associated with the Company's
sale of receivables facility will be included with "Cash Flows from
Financing Activities", see "Sale of Receivables" included in Note 3.
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7. COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
Following is certain information concerning the Company's obligations under
operating leases:
(1) Principally consisting of rental agreements for building space, data
processing equipment and vehicles (including major work equipment).
Lease payments related to assets transferred under the Company's leasing
arrangements (see "Other Long-Term Financing" included in Note 3) are included
in the preceding table for only their primary (non-cancelable) term. Subsequent
to the primary term, the Company could terminate its obligations under these
arrangements by electing to purchase the relevant assets for an amount
approximating fair market value. Total rental expense for all leases was $33.4
million, $48.9 million and $36.8 million in 1996, 1995 and 1994, respectively.
LETTERS OF CREDIT
At December 31, 1996, the Company was obligated under letters of credit
incidental to its ordinary business operations totalling approximately $21.7
million.
INDEMNITY PROVISIONS
In June 1993, the Company completed the sale of Louisiana Intrastate Gas
Corporation ("LIG"), its former subsidiary engaged in the intrastate pipeline
and liquids extraction business, to Equitable Resources, Inc. In December 1992,
the Company completed the sale of Arkla Exploration Company ("AEC"), its former
subsidiary engaged in oil and gas exploration and production activities, to
Seagull Energy Corporation. In June 1991, the Company completed the sale of Dyco
Petroleum Company ("Dyco"), the oil and gas exploration and production company
acquired in conjunction with the Company's acquisition of Diversified Energies
Inc., to Continental Drilling Company, Inc., a subsidiary of Samson Investment
Company. In each instance, the relevant sale agreement required the Company to
indemnify the purchaser against certain exposures, for which the Company has
established reserves based on, among other factors, its estimates of potential
claims. These reserves are included in the Company's Consolidated Balance Sheet
under the caption "Estimated obligations under indemnification provisions of
sale agreements".
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been transferred pursuant to a sale of receivables facility, see "Sale of
Receivables" included in Note 3.
GAS PURCHASE CLAIMS
In conjunction with settlements of "take-or-pay" claims, the Company has prepaid
for certain volumes of gas, which prepayments have been recorded at their net
realizable value and, to the extent that the Company is unable to realize at
least the carrying amount as the gas is delivered and sold, the Company's
earnings will be adversely affected, although such impact is not expected to be
material. In addition to these prepayments, the Company is a party to a number
of agreements which require it to either purchase or sell gas in the future at
prices which may differ from then-prevailing market prices or which require it
to deliver gas at a point other than the expected receipt point for volumes to
be purchased. As discussed under "Credit Risk and Off-Balance-Sheet Risk"
following, the Company operates an ongoing risk management program designed to
eliminate or limit the Company's exposure from its obligations under these
purchase/sale commitments. To the extent that the Company expects that these
commitments will result in losses over the contract term, the Company has
established reserves equal to such expected losses.
TRANSPORTATION AGREEMENT
The Company had an agreement ("the ANR Agreement") with ANR Pipeline Company
("ANR") which contemplated a transfer to ANR of an interest in certain of the
Company's pipeline and related assets, representing capacity of 250
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MMcf/day, and pursuant to which ANR had advanced $125 million to the Company.
The ANR Agreement has been restructured as a lease of capacity and, after
refunds of $50 million and $34 million in 1995 and 1993, respectively, the
Company currently retains $41 million (recorded as a liability) in exchange for
ANR's use of 130 MMcf/day of capacity in certain of the Company's transportation
facilities. The level of transportation will decline to 100 MMcf/day in the year
2003 with a refund of $5 million to ANR and the ANR Agreement will terminate in
2005 with a refund of the remaining balance.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company's gas supply, marketing, gathering and transportation activities
subject the Company's earnings to variability based on fluctuations in both the
market price of natural gas and the value of transportation as measured by
changes in the delivered price of natural gas at various points in the nation's
natural gas grid. In order to mitigate the financial risk associated with these
activities both for itself and for certain customers who have requested the
Company's assistance in managing similar exposures, the Company routinely enters
into natural gas swaps, futures contracts and options, collectively referred to
in this discussion as "derivatives". The use of derivatives for the purpose of
reducing exposure to risk is generally referred to as hedging and, through
deferral accounting, results in matching the financial impact of these
derivative transactions with the cash impact resulting from consummation of the
transactions being hedged, see "Accounting for Price Risk Management Activities"
included in Note 1.
The futures contracts are purchased and sold on the NYMEX and generally are used
to hedge a portion of the Company's storage gas, manage intra-month and
inter-month actual and anticipated short or long commodity positions and provide
risk management assistance to certain customers, to whom the cost of the
derivative activity is generally passed on as a component of the sales price of
the service being provided. Futures contracts are also utilized to fix the price
of compressor fuel or other future operational gas requirements, although usage
to date for this purpose has not been material. The options are entered into
with various third parties and principally consist of options which serve to
limit the year-to-year escalation from January 1998 to April 1999 in the
purchase price of gas which the Company is committed to deliver to a
distribution affiliate. These options covered 2.4 Bcf, 13.2 Bcf and 30.5 Bcf at
December 31, 1996, 1995 and 1994, respectively and, due to their nature and
term, have no readily determinable fair market value. The Company previously
established a reserve equal to its projected maximum exposure to losses during
the term of this commitment and, accordingly, no impact on earnings is expected.
The Company also utilizes options in conjunction with meeting customers' needs
for custom risk management services and for other limited purposes. The Company
had an immaterial amount of such options outstanding at December 31, 1996. The
impact of such options was to decrease 1996 earnings by approximately $2.6
million and the effect on prior periods was not material. The swaps, also
entered into with various third parties, are principally associated with the
Company's marketing and transportation activities and generally require that one
party pay either a fixed price or fixed differential from the NYMEX price per
MMBtu of gas while the other party pays a price based on a published index.
These swaps allow the Company to (1) commit to purchase gas at one location and
sell it at another location without assuming unacceptable risk with respect to
changes in the cost of the intervening transportation, (2) effectively set the
value to be received for transportation of certain volumes on the Company's
facilities in the future and (3) effectively fix the base price for gas to be
delivered in conjunction with the commitment described preceding. None of these
derivatives are held for speculative purposes and the Company's risk management
policy requires that positions taken in derivatives be offset by positions in
physical transactions (actual or anticipated) or in other derivatives.
In the table which follows, the term "notional amount" refers to the contract
unit price times the contract volume for the relevant derivative category and,
in general, such amounts are not indicative of the cash requirements associated
with these derivatives. The notional amount is intended to be indicative of the
Company's level of activity in such derivatives, although the amounts at risk
are significantly smaller because, in view of the price movement correlation
required for hedge accounting, changes in the market value of these derivatives
generally are offset by changes in the value associated with the underlying
physical transactions or in other derivatives. When derivative positions are
closed out in advance of the underlying commitment or anticipated transaction,
however, the market value changes may not offset due to the fact that price
movement correlation ceases to exist when the positions are closed. Under such
circumstances, gains or losses are deferred and recognized when the underlying
commitment or anticipated transaction was scheduled to occur. Following is
certain information concerning the Company's derivative activities:
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(1) The financial impact of these swaps was to increase(decrease) earnings by
$(1.0) million, $1.0 million and $2.8 million during 1996, 1995 and 1994,
respectively, as swap transactions were matched with hedged transactions
during these periods.
(2) Represents the estimated amount which would have been realized upon
termination of the relevant derivatives as of the date indicated. The
amount which is ultimately charged or credited to earnings is affected by
subsequent changes in the market value of these derivatives and, in the
case of certain commitments described preceding, no earnings impact is
expected due to existing accruals. Swaps associated with these commitments
and included in the above totals had fair market values of $2.8 million,
$(1.0) million and $(17.6) million at December 31, 1996, 1995 and 1994,
respectively.
(3) There was no material financial impact from these futures contracts in 1994
and the effect during 1996 and 1995 was to decrease earnings by $9.3
million and $4.1 million, respectively, as futures transactions were
matched with hedged transactions during these periods. At December 31,
1996, the Company had deferred losses of approximately $11.9 million
associated with expected sales under "peaking" contracts with certain
customers which, in effect, give the customer a "call" on certain volumes
of gas. All such losses were recognized in January 1997 when the
anticipated transactions were scheduled to occur.
While, as yet, the Company has experienced no significant losses due to the
credit risk associated with these arrangements, the Company has
off-balance-sheet risk to the extent that the counterparties to these
transactions may fail to perform as required by the terms of each such contract.
In order to minimize this risk, the Company enters into such transactions solely
with firms of acceptable financial strength, in the majority of cases limiting
such transactions to counterparties whose debt securities are rated "A" or
better by recognized rating agencies. For long-term arrangements, the Company
periodically reviews the financial condition of such firms in addition to
monitoring the effectiveness of these financial contracts in achieving the
Company's objectives. Should the counterparties to these arrangements fail to
perform, the Company would seek to compel performance at law or otherwise, or to
obtain compensatory damages in lieu thereof, but the Company might be forced to
acquire alternative hedging arrangements or be required to honor the underlying
commitment at then-current market prices. In such event, the Company might incur
additional loss to the extent of amounts, if any, already paid to the
counterparties. In view of its criteria for selecting counterparties, its
process for monitoring the financial strength of these counterparties and its
experience to date in successfully completing these transactions, the Company
believes that the risk of incurring a significant loss due to the nonperformance
of counterparties to these transactions is minimal.
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LITIGATION
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the merger between the Company and Houston
Industries (see "Merger With Houston Industries" included in Note 1) or to
rescind such merger and/or to recover damages in the event that the Transaction
is consummated. The complaint alleges, among other things, that the merger
consideration is inadequate, that the Company's Board of Directors breached its
fiduciary duties and that Houston Industries aided and abetted such breaches of
fiduciary duties. In addition, the plaintiff seeks certification as a class
action. The Company believes that the claims are without merit and intends to
vigorously defend against the lawsuit. Management believes that the effect on
the Company's results of operations, financial position or cash flows, if any,
from the disposition of this matter will not be material.
The Company is a party to litigation (other than that specifically noted) which
arises in the normal course of business. Management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. Management believes that the effect on
the Company's results of operations, financial position or cash flows, if any,
from the disposition of these matters will not be material.
ENVIRONMENTAL MATTERS
The Company and its predecessors operated a manufactured gas plant ("MGP")
adjacent to the Mississippi River in Minnesota known as the former Minneapolis
Gas Works ("FMGW") until 1960. The Company is working with the Minnesota
Pollution Control Agency to implement an appropriate remediation plan. There are
six other former MGP sites in the Company's Minnesota service territory. Of the
six sites, the Company believes that two were neither owned nor operated by the
Company; two were owned at one time but were operated by others and are
currently owned by others; and one was operated by the Company and is now owned
by others. The Company believes it has no liability with respect to the sites it
neither owned nor operated.
At December 31, 1996, the Company has estimated a range of $10 million to $170
million for possible remediation of the Minnesota sites. The low end of the
range was determined using only those sites presently owned or known to have
been operated by the Company, assuming the Company's proposed remediation
methods. The upper end of the range was determined using the sites once owned by
the Company, whether or not operated by the Company, using more costly
remediation methods. The cost estimates for the FMGW site are based on studies
of that site. The remediation costs for other sites are based on industry
average costs for remediation of sites of similar size. The actual remediation
costs will be dependent upon the number of sites remediated, the participation
of other potentially responsible parties, if any, and the remediation methods
used.
In its 1993 rate case, Minnegasco was allowed $2.1 million annually to recover
amortization of previously deferred and ongoing clean-up costs. Any amounts in
excess of $2.1 million annually were deferred for future recovery. In its 1995
rate case, Minnegasco asked that the annual allowed recovery be increased to
approximately $7 million and that such costs be subject to a true-up mechanism
whereby any over or under recovered amounts, net of certain insurance recoveries
as described following, plus carrying charges, would be deferred for recovery or
refund in the next rate case. Such accounting was approved by the Minnesota
Public Utilities Commission ("MPUC") and was implemented effective October 1,
1995. The amount of insurance recoveries to be flowed back to ratepayers is
determined by multiplying insurance recoveries received by the ratio of total
costs incurred to-date as a percentage of the probable total costs of
environmental remediation. At December 31, 1996 and 1995, the Company had
under-collected, through rates, net environmental clean-up costs of $1.4 million
and $1.3 million, respectively. In addition, at December 31, 1996 and 1995, the
Company had received insurance proceeds that will be refunded through rates in
the future as clean-up expenditures are made of $4.3 million and $3.3 million,
respectively. At December 31, 1996 and 1995, the Company had recorded a
liability of $35.9 million and $45.2 million, respectively, to cover the cost of
future remediation. In addition, the Company has receivables from insurance
settlements of $5.2 million at December 31, 1996. These insurance settlements
will be collected through 1999. The Company expects that the majority of its
accrual as of December 31, 1996 will be expended within the next five years. In
accordance with the provisions of SFAS 71, a regulatory asset has been recorded
equal to the liability accrued. The Company is continuing to pursue recovery of
at
11
least a portion of these costs from insurers. The Company believes the
difference between any cash expenditures for these costs and the amounts
recovered in rates during any year will not be material to the Company's overall
cash requirements.
In addition to the Minnesota MGP sites described above, the Company's
distribution divisions are investigating the possibility that the Company or
predecessor companies may be or may have been associated with other MGP sites in
the service territories of the distribution divisions. At the present time, the
Company is aware of some plant sites in addition to the Minnesota sites and is
investigating certain other locations. While the Company's evaluation of these
other MGP sites remains in its preliminary stages, it is likely that some
compliance costs will be identified and become subject to reasonable
quantification. To the extent that such potential costs are quantified, as with
the Minnesota remediation costs for MGP described preceding, the Company expects
to provide an appropriate accrual and seek recovery for such remediation costs
through all appropriate means, including regulatory relief.
On October 24, 1994, the United States Environmental Protection Agency advised
the Company that MRT and a number of other companies have been named under
federal law as potentially responsible parties for a landfill site in West
Memphis, Arkansas and may be required to share in the cost of remediation of
this site. However, considering the information currently known about the site
and the involvement of MRT, the Company does not believe that this matter will
have a material adverse effect on its financial position, results of operations
or cash flows.
On December 18, 1995, the Louisiana Department of Environmental Quality advised
the Company that the Company, through one of its subsidiaries and together with
several other unaffiliated entities, had been named under state law as a
potentially responsible party with respect to a hazardous substance site in
Shreveport, Louisiana and may be required to share in the remediation cost, if
any, of the site. However, considering the information currently known about the
site and the involvement of the Company and its subsidiaries with respect to the
site, the Company does not believe that the matter will have a material adverse
effect on its financial position, results of operations or cash flows.
In addition, the Company, as well as other similarly situated firms in the
industry, is investigating the possibility that it may elect or be required to
perform remediation of various sites where meters containing mercury were
disposed of improperly, or where mercury from such meters may have leaked or
been disposed of improperly. While the Company's evaluation of this issue
remains in its preliminary stages, it is likely that compliance costs will be
identified and become subject to reasonable quantification.
At December 31, 1996 and 1995, the Company had recorded an accrual of $3.3
million (with a maximum estimated exposure of approximately $18 million) and an
offsetting regulatory asset for environmental matters in connection with a
former fire training facility and a landfill for which future remediation may be
required. This accrual is in addition to the accrual for MGP sites as discussed
preceding.
While the nature of environmental contingencies makes complete evaluation
impracticable, the Company currently is aware of no other environmental matter
which could reasonably be expected to have a material impact on its results of
operations, financial position or cash flows.
12
MATERIAL CHANGES IN THE RESULTS
OF CONTINUING OPERATIONS
GENERAL
In recognition of the manner in which the Company manages its portfolio of
businesses, and in order to facilitate a more detailed understanding of the
various activities in which the Company engages, the Company has segregated its
results of operations into (1) Natural Gas Distribution, (2) Interstate
Pipelines, (3) Wholesale Energy Marketing, (4) Natural Gas Gathering, (5)
Retail Energy Marketing and (6) Corporate and Other. The Company's results of
operations are seasonal due to weather-related fluctuations in the demand for
and price of natural gas although, as discussed following and elsewhere herein,
(1) the Company has obtained rate design changes in its rate-regulated
businesses which generally have reduced the sensitivity of the Company's
earnings to seasonal weather patterns (further such changes may occur) and (2)
the Company is seeking to derive a larger portion of its earnings from
businesses which exhibit less earnings seasonality.
Since the Company's December 1992 sale of its oil and gas exploration
and production business, the substantial majority of the Company's earnings
have been attributable to operations which are rate regulated. While these
businesses have been subjected to varying levels of competition through changes
in the form of regulation (further such changes may occur), in general, they
continue to be regulated on a cost-of-service basis and the potential for
growth in earnings and increased rates of return is limited. The Company seeks
to improve its returns from these businesses through increased efficiency,
aggressive marketing and by rate initiatives which allow these businesses to
compete more effectively and retain more of the value added through improved
operations and expanded services.
The Company continues to believe that its greatest potential for
significant increases in overall profitability lies in those businesses which
are, in some instances, subject to regulation as to the nature of services
offered, the manner in which services are provided or the allocation of joint
costs between cost-of-service regulated and other operations, but generally are
not subject to direct regulation as to the rates which may be charged. Such
operations are sometimes referred to herein for convenience as "unregulated".
The Company has separated its strategically significant unregulated activities
into discrete management units and formulated plans for increasing the future
financial contribution from these businesses. The Company has and expects to
continue to (1) expand both the range of products and services offered by these
businesses and the geographic areas served and (2) increase the percentage of
the Company's overall earnings derived from these activities.
In addition, the Company is investigating opportunities for
international investment. To date, the Company's efforts have focused on
opportunities emerging in Latin America due to privatization initiatives
currently underway in a number of countries, as well as broad-based efforts to
encourage international investment. While such investments involve increased
risks such as political, economic or regulatory instability and foreign
currency exchange rate fluctuations, the Company believes that, together with
carefully selected partners (both within the target countries and otherwise),
it can effectively apply its natural gas industry expertise to selected
projects in Latin America, thereby increasing its overall returns on invested
capital while keeping the increased risk within acceptable limits. In general,
the international investment is expected to build up gradually over a period of
years as the Company (1) identifies and creates working relationships with
strategic business partners, (2) selects projects which meet its risk/return
requirements, (3) develops specific country experience and (4) in some cases,
increases its investment in specific projects as facilities are constructed,
see the following discussion and "Capital Expenditures - Continuing Operations"
under "Net Cash Flows from Investing Activities" elsewhere herein.
In early 1997, the Company learned that four consortiums ("the
Consortiums"), each of which included the Company, were the apparent successful
bidders for the right to build and operate natural gas distribution facilities
in each of four defined service areas ("the Concessions") within Colombia.
Contracts, which extend through the year 2014 and grant the exclusive right to
distribute gas to consumers of less than 500 Mcf per day (and the right to
compete for other customers), are expected to be awarded in April 1997. The
Company estimates that the Concessions ultimately will have approximately
400,000 customers, connected over approximately a five-year period at a total
cost of approximately $160 million, with construction expected to begin no
later than the fourth quarter of 1997. The Company's ownership interest in the
Consortiums, while subject to change through continuing negotiations with its
existing and potential partners ranges from 15% to approximately 33% and, based
on the expected number of customers, represents a weighted average ownership
interest of approximately 23%. Depending upon, among other factors, its
ownership percentage and success in finalizing financing arrangements at
estimated levels and with expected terms (see
13
the discussion following), the Company currently estimates that the net cash
outflows to support its investment in the Concessions will not exceed
approximately $4 million in any year, and that its investment in the
Concessions will become a net source of cash in approximately year four.
Debt is currently expected to make up a significant portion of the
financing for the Concessions in the early years of the project, reaching a
maximum level of approximately $90 million and declining thereafter. While such
debt is expected to be without direct recourse to members of the Consortiums
("the Partners"), the terms of the debt will likely require that each Partner
enter into an agreement which commits it to make pro rata capital contributions
as funds are borrowed to finance construction, and that lenders will be granted
a security interest in such agreements. The Company is considering extending an
offer of support to its Partners such that, in the event that any Partner fails
to make capital contributions as required, the Company would make such
contributions and assume the underlying ownership interest. The Company
currently estimates that, in the event this arrangement is agreed to by all
parties and finalized, and the Company is required to assume all such
interests, the Company's maximum investment in the Concessions will not exceed
$50 million and its net cash outflows in support of the Concessions will not
exceed $18 million in any year.
In January 1997, the Company participated in a bid for a permit
authorizing the construction, ownership and operation of a natural gas
distribution system for the geographic area that includes the cities of
Chihuahua, Delicias and Cuauchtemoc/Anahuac in North Central Mexico. In March
1997, the Company learned that its group was not the successful bidder. The
Company had previously announced its intention to participate in a similar
bidding process for a permit to provide natural gas distribution service to all
or a portion of Mexico City, although no date has yet been set for submission
of bids.
REGULATORY MATTERS
In general, the Company's interstate pipelines are subject to regulation by the
FERC, while its natural gas distribution operations are subject to regulation
at the state or municipal level. Historically, all of the Company's
rate-regulated businesses have followed the accounting guidance contained in
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation" ("SFAS 71"). The Company discontinued
application of SFAS 71 to its NorAm Gas Transmission Company subsidiary ("NGT")
effective with year-end 1992 reporting, see "Interstate Pipelines" elsewhere
herein. As a result of the continued application of SFAS 71 to Mississippi
River Transmission Corporation ("MRT") and the Company's natural gas
distribution operations, the Company's consolidated financial statements
contain certain assets and liabilities which would not be recognized by
unregulated entities. In addition to regulatory assets related to
postretirement benefits other than pensions, the Company's only other
significant regulatory asset is related to anticipated environmental
remediation costs, see Note 5 of the accompanying Notes to Consolidated
Financial Statements and "Environmental Matters" under "Commitments and
Contingencies" elsewhere herein. Following are recent significant regulatory
actions and developments.
NGT's Negotiated Rate Filing (Docket No. RP96-200), accepted by the
FERC on April 25, 1996, allowed NGT's rates to exceed the maximum cost-based
rates set forth in its filed tariff and/or to deviate from the current
FERC-mandated rate design. NGT has negotiated certain transactions which
provide for shippers' rates to be based on various factors such as gas price
differentials between the east and west sides of the NGT system. Therefore, in
some instances, NGT will charge and collect a negotiated rate which exceeds its
then-current maximum filed tariff rate. Appeals of the FERC's negotiated rate
policy, as well as the specific authorization granted to NGT to charge
negotiated rates, have been filed with the U.S. Court of Appeals, D.C. Circuit.
Until such time as these appeals are resolved, some uncertainty will exist as
to whether the Company may be required to refund any amounts associated with
transactions billed at above the maximum tariff rate. The Company currently
believes that any such refund will not be material. The FERC accepted NGT's 4th
annual FERC Order 528 filing (Docket No. RP96-167) effective April 1, 1996,
which retained the $0.03 per MMBtu commodity surcharge for continued recovery
of 75% of eligible take-or-pay costs, to the extent that collection of such
costs is supported by market conditions. The recovery of these costs, which
commenced in 1992, will continue through the year 2002 although, as a result of
the discontinuance of the application of SFAS 71 to NGT as described preceding,
no asset has been recorded in anticipation of recovery. Additionally, in April
1996, the FERC issued certificate orders granting (1) abandonment of NGT's
Collinson Storage Facility and associated facilities and equipment (Docket No.
CP95- 250), which will not result in a material gain or loss upon abandonment
and will not be abandoned until all gas has been recovered and (2) abandonment
and transfer of NGT's Line O West facilities to NorAm Field Services Corp.
("NFS") (Docket No. RP96-105), allowing NGT to divest itself of certain
non-core facilities which supported the gas supply function in a time when NGT
was principally a merchant of natural gas.
14
NGT's certificated Line F Project, constructed at a total cost of
approximately $17 million, replaced a 30 mile section of the existing Line F
from Ruston to Sterlington, Louisiana, and upgraded the maximum allowed
operating pressure of the line to 1200 psig. This replacement project was
placed in service on October 31, 1996 and allows NGT to receive gas from an
interconnect with MRT located near NGT's Ruston Compressor Station. Finally, on
November 1, 1996, both MRT and NGT filed to revise their FERC tariffs,
incorporating the Gas Industry Standards Board standards in compliance with
FERC Order 587 (Docket No. RM96-1). These filings set forth each company's
standard procedures for business practices supporting nominations, allocations,
balancing, measurement, invoicing, capacity release, and standardization of
electronic communications between pipelines and their customers. Pursuant to a
FERC acceptance order, both NGT and MRT revised and refiled specified sections
of these tariffs in February 1997.
In April 1996, MRT filed a FERC Section 4 rate case (Docket No.
RP96-199) pursuant to the settlement entered into in MRT's last rate case
(Docket No. RP93-4). MRT's proposed tariff rates would increase revenues
derived from jurisdictional service by $14.7 million annually. Motion rates,
subject to refund, were implemented October 1, 1996. As a result of a
prehearing conference in December 1996, another procedural schedule was
established, setting a hearing date of July 29, 1997.
MRT filed an application (Docket No. CP95-376) requesting spindown of
all of its gathering facilities. In May 1996, the FERC issued an order
approving MRT's abandonment of its off-system gathering facilities to NFS and
further declaring such facilities exempt from FERC jurisdiction. In March 1996,
MRT filed a second application (Docket No. CP96- 268), which is now pending,
seeking (1) FERC approval to abandon its remaining gathering facilities by
transfer and sale to NFS and (2) a FERC declaration that these facilities are
exempt from FERC jurisdiction.
Entex was granted annualized rate increases totaling $5.4 million
during 1996. In addition to annual cost-of- service adjustments in three Texas
operating divisions (approximately $0.6 million on an annualized basis),
performance- based rates were approved and implemented in Louisiana
(approximately $2.7 million on an annualized basis, effective in June ) and
Mississippi (approximately $2.1 million on an annualized basis, effective in
October). In both Louisiana and Mississippi, Entex will be allowed to earn a
return on equity ("ROE") within an approved range. Earnings will be monitored
by the public service commissions of the respective states and, while the
provisions in each state differ slightly, to the extent that Entex's ROE falls
below the lower bounds or exceeds the upper bounds of the approved range,
adjustments will be made to either adjust rates upward or refund excess
earnings to customers.
In April 1996, the Minnesota Public Utilities Commission (the "MPUC")
voted to approve Minnegasco's Performance-Based Gas Purchasing Plan (the
"PBR"), effective from September 1, 1995 to June 30, 1998. To the extent that
Minnegasco's actual purchased gas cost is either significantly higher or lower
than specified benchmarks, the PBR will require that Minnegasco and its
customers share in the savings or additional cost, resulting in a maximum
reward or penalty of up to 2% of annual gas cost (e.g. approximately $10
million using Minnegasco's 1996 gas cost) for Minnegasco during any year.
Minnegasco made a compliance filing with the MPUC on November 1, 1996, the
first year of the PBR, which filing was approved for approximately $1 million
in March 1997.
In June 1996, the MPUC issued its order in Minnegasco's August 1995
rate case. The MPUC granted an annual increase of $12.9 million as compared to
the requested increase of $24.3 million. Interim rates reflecting an increase
of $17.8 million had been put into effect in October 1995 subject to refund. As
a part of its decision, the MPUC granted Minnegasco full recovery of its
ongoing net environmental costs through the use of a true-up mechanism whereby
any amounts collected in rates which differ from actual costs incurred, plus
carrying charges, will be deferred for recovery or refund in the next rate
case. Minnegasco requested reconsideration on several issues. Among them were
(1) a request to give effect, in this rate case, to the Minnesota Supreme
Court's (the "Court") recent rulings (see the discussion following), and (2) a
request to deduct from any interim rate refund the additional amount that
Minnegasco would have realized from its 1993 rate case by applying the Court's
ruling to that case, which remained on appeal.
The MPUC decided in Minnegasco's 1993 rate case that (1) Minnegasco's
unregulated appliance sales and service operations are required to pay the
regulated utility operations a fee for the use of Minnegasco's name, image and
reputation ("goodwill") and (2) a portion of the cost of responding to certain
gas leak calls not be allowed in rates. Minnegasco appealed those decisions to
the Court of Appeals. On June 13, 1996, in a case appealed prior to the 1993
rate case, the Court reversed the MPUC's decisions on these two issues, finding
in Minnegasco's favor and, in July, the Court denied the MPUC's request for
rehearing.
In its December 4, 1996 Order After Reconsideration, the MPUC
determined that Minnegasco was entitled to an annual rate increase of $13.3
million as compared to the $12.9 million granted in June 1996. The MPUC decided
that Minnegasco's unregulated appliance sales and service operations should not
pay a fee for goodwill associated with the
15
Minnegasco name, but refused to allow Minnegasco to recover certain costs
associated with gas leak check calls, and did not approve Minnegasco's request
with respect to the 1993 rate case costs. An appeal related to the 1993 rate
case is pending before the Court of Appeals. Minnegasco requested and, on
February 20, 1997, the MPUC voted to grant a stay of the Commission's order
pending Minnegasco's appeal of the gas leak issue in the 1995 rate case.
Minnegasco is accruing for any necessary interim rate refunds should the Court
deny Minnegasco's appeal.
CHANGE IN ESTIMATED SERVICE LIVES OF CERTAIN ASSETS
Pursuant to an updated study of the useful lives of certain assets, in July
1995, the Company changed the depreciation rates associated with certain of its
natural gas pipeline and gathering assets, see "Interstate Pipelines" and
"Natural Gas Gathering" elsewhere herein. This change had the effect of
increasing the Company's 1995 income before extraordinary item by approximately
$3.2 million ($0.03 per share) and represents an annualized increase of
approximately $6.5 million.
16
ITEM 3. LEGAL PROCEEDINGS
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the Transaction or to rescind the Transaction
and/or to recover damages in the event that the Transaction is consummated. The
complaint alleges, among other things, that the merger consideration is
inadequate, that the Company's Board of Directors breached its fiduciary duties
and that Houston Industries aided and abetted such breaches of fiduciary duties.
In addition, the plaintiff seeks certification as a class action. The Company
believes that the claims are without merit and intends to vigorously defend
against the lawsuit. The Company does not believe that the matter will have a
material adverse effect on the financial position, results of operations or cash
flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company, that the Company, through one of its subsidiaries, and
together with several other unaffiliated entities, have been named under state
law as potentially responsible parties with respect to a hazardous substance
site in Shreveport, Louisiana and may be required to share in the remediation
cost, if any are incurred. However, considering the information currently known
about the site and the involvement of the Company and its subsidiaries with
respect to the site, the Company does not believe that the matter will have a
material adverse effect on the financial position, results of operations or cash
flows of the Company.
On October 24, 1994, the United States Environmental Protection Agency (the
"EPA") advised the Company that MRT and a number of other companies have been
named under federal law as potentially responsible parties for a landfill site
in West Memphis, Arkansas and may be required to share in the cost of
remediation of this site. The EPA is continuing to investigate the possibility
that other companies may have sent waste material to this site. Considering the
information currently known about the site and the involvement of MRT, the
Company does not believe that this matter will have a material adverse effect on
the financial position, results of operations or cash flows of the Company.
The Company is a party to litigation (other than that specifically noted)
which arises in the normal course of business. Management regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. Management believes
that the effect on the Company's results of operations, financial position or
cash flows, if any, from the disposition of theses matters will not be material.